Autonomous tool

ABSTRACT

A method, system, and apparatus for determining the location of a tool traveling down a wellbore by measuring a first borehole magnetic anomaly with respect to time at two known locations on a tool, comparing the time difference between the two measurements, then calculating the velocity of the tool based on the comparison, then further calculating the distance traveled by the tool in the wellbore based on the velocity calculation, then executing a series of commands at a predetermined location in the wellbore.

RELATED APPLICATIONS

This application is a U.S. continuation application of U.S.Nonprovisional patent application Ser. No. 16/971,976, filed Aug. 21,2020, which is a 371 of International Application No. PCT/US19/19267,filed Feb. 22, 2019, which claims priority to U.S. ProvisionalApplication No. 62/634,740, filed on Feb. 23, 2018.

BACKGROUND OF THE INVENTION

Generally, when completing a subterranean well for the production offluids, minerals, or gases from underground reservoirs, several types oftubulars are placed downhole as part of the drilling, exploration, andcompletions process. These tubulars can include casing, tubing, pipes,liners, and devices conveyed downhole by tubulars of various types. Eachwell is unique, so combinations of different tubulars may be loweredinto a well for a multitude of purposes.

A subsurface or subterranean well transits one or more formations. Theformation is a body of rock or strata that contains one or morecompositions. The formation is treated as a continuous body. Within theformation hydrocarbon deposits may exist. Typically a wellbore will bedrilled from a surface location, placing a hole into a formation ofinterest. Completion equipment will be put into place, including casing,tubing, and other downhole equipment as needed. Perforating the casingand the formation with a perforating gun is a well-known method in theart for accessing hydrocarbon deposits within a formation from awellbore.

Explosively perforating the formation using a shaped charge is a widelyknown method for completing an oil well. A shaped charge is a term ofart for a device that when detonated generates a focused explosiveoutput. This is achieved in part by the geometry of the explosive inconjunction with an adjacent liner. Generally, a shaped charge includesa metal case that contains an explosive material with a concave shape,which has a thin metal liner on the inner surface. Many materials areused for the liner; some of the more common metals include brass,copper, tungsten, and lead. When the explosive detonates the liner metalis compressed into a super-heated, super pressurized jet that canpenetrate metal, concrete, and rock.

A perforating gun has a gun body. The gun body typically is composed ofmetal and is cylindrical in shape. Within a typical gun tube is a chargeholder or carrier tube, which is a tube that is designed to hold theactual shaped charges. The charge holder will contain cutouts calledcharge holes where the shaped charges will be placed.

A shaped charge is typically detonated by a booster or igniter. Shapedcharges may be detonated by electrical igniters, pressure activatedigniters, or detonating cord. One way to ignite several shaped chargesis to connect a common detonating cord that is placed proximate to theigniter of each shaped charge. The detonating cord is comprised ofmaterial that explodes upon ignition. The energy of the explodingdetonating cord can ignite shaped charges that are properly placedproximate to the detonating cord. Often a series of shaped charges maybe daisy chained together using detonating cord.

Another type of explosive used in completions is a jet cutter. This isan explosive that creates a radial explosion. It can be used to severtubulars, including downhole casing.

A firing head is used to detonate the detonating cord in the perforatinggun. The firing head may be activated by an electrical signal.Electricity may be provided by a wireline that ties into the cableheadat the top of a tool string. The electrical signal may have to travelthrough several components, subs, and tools before it gets to the firinghead. A reliable electrical connector is needed to ensure the electricalsignal can easily pass from one component to the next as it moves downthe tool string. The electrical signal is typically grounded against thetool string casing. As a result, the electrical connections must beinsulated from tool components that are in electrical contact with thetool string casing.

SUMMARY OF EXAMPLE EMBODIMENTS

An example embodiment may include an apparatus for use downholecomprising a top housing with a first end, a second end, an axis, amiddle housing with a first end located proximate to the second end ofthe top housing, and a second end, wherein the middle housing is coaxialwith the axis, a braking housing with a first end located proximate tothe second end of the middle housing, and a second end, wherein thebraking housing is coaxial with the axis, a bottom housing with a firstend located proximate to the second end of the braking housing, and asecond end, wherein the bottom housing is coaxial with the axis, a firstmagnetic anomaly sensor located within the top housing, a secondmagnetic anomaly sensor located within the bottom housing and located afixed axial distance from the first magnetic anomaly sensor, a processorlocated within the middle housing, operatively connected to the firstmagnetic anomaly sensor and the second magnetic anomaly sensor, whereinthe processor calculates the velocity of the apparatus based oncomparing measurements taken from the first magnetic anomaly sensor andthe second magnetic anomaly sensor, at least one radially retractablebraking arm located in the braking housing, wherein the processor cancommand the braking arm to extend against a wellbore and stop thedownhole descent of the apparatus at a predetermined location.

A variation of the example embodiment may include having a plurality ofelectromagnetic coils disposed within the first magnetic anomaly sensor.It may have a first electromagnetic coil disposed within the firstmagnetic anomaly sensor adapted to generate an electromagnetic field.There may be a second electromagnetic coil disposed within the firstmagnetic anomaly sensor adapted to generate an electromagnetic field.There may be a third electromagnetic coil disposed within the firstmagnetic anomaly sensor adapted to detect an electromagnetic field.There may be a fourth electromagnetic coil disposed within the firstmagnetic anomaly sensor adapted to detect an electromagnetic field.There may be a fifth electromagnetic coil disposed within the firstmagnetic anomaly sensor adapted to detect an electromagnetic field.There may be a sixth electromagnetic coil disposed within the firstmagnetic anomaly sensor adapted to detect an electromagnetic field. Theat least one radially retractable braking arm may be a plurality ofradially retractable braking arms located about the axis. It may includea perforating gun assembly coupled to the top housing, wherein theprocessor is electrically coupled to the perforating gun assembly andcan fire the perforating gun assembly at a predetermined location. Itmay include a cutter assembly coupled to the top housing, wherein theprocessor is electrically coupled to the cutter assembly and can firethe cutter assembly at a predetermined location. It may include asetting tool coupled to the bottom housing, wherein the processor iselectrically coupled to the setting tool and can activate the settingtool at a predetermined location to plug the wellbore.

A variation of the example embodiment may include a first sub coupled tothe first end of the top housing. It may include a second sub coupled tothe second end of the top housing and coupled to the first end of thebottom housing. It may include a third sub coupled to the second end ofthe bottom housing. The first centralizer may have a hollow cylindricalshape. The second centralizer may have a substantially hollowcylindrical shape.

A variation of the example embodiment may include a cylindrical corelocated coaxial with the axis and passing through the first, second,third, fourth, fifth, and sixth electromagnets. There may be a pluralityof electromagnetic coils disposed within the second magnetic anomalysensor. There may be a seventh electromagnetic coil disposed within thesecond magnetic anomaly sensor adapted to generate an electromagneticfield. It may have an eighth electromagnetic coil disposed within thesecond magnetic anomaly sensor adapted to generate an electromagneticfield. It may have a ninth electromagnetic coil disposed within thesecond magnetic anomaly sensor adapted to detect an electromagneticfield. It may have a tenth electromagnetic coil disposed within thesecond magnetic anomaly sensor adapted to detect an electromagneticfield. It may have an eleventh electromagnetic coil disposed within thesecond magnetic anomaly sensor adapted to detect an electromagneticfield. It may have a twelfth electromagnetic coil disposed within thesecond magnetic anomaly sensor adapted to detect an electromagneticfield.

A variation of the example embodiment may include a cylindrical corelocated coaxial with the axis and passing through the first, second,third, fourth, fifth, and sixth electromagnets. The processor includes adata logger. The processor may include a plurality of processors. Theprocessor may compute the velocity by comparing measurements taken fromthe first magnetic anomaly sensor and the second magnetic anomalysensor. It may include a first centralizer surrounding a portion of thefirst end of the top housing. It may include a second centralizersurrounding a portion of the second end of the top housing and a portionof the second end of the bottom housing. The top housing may be composedof a frangible material. The top housing may be composed of a ceramicmaterial. The top housing may be composed of steel. The bottom housingmay be composed of a frangible material. The bottom housing may becomposed of a ceramic material. The bottom housing may be composed ofsteel. The processor may calculate distance traveled by integrating thecalculated velocity with respect to time. The processor may calculatethe distance traveled using a summation of the calculated velocity withrespect to time. The processor may calculate the distance traveled byaveraging the calculated velocity over a plurality of measurements andmultiplying by time. The processor may calculate the distance traveledusing a piecewise summation with respect to time.

An example embodiment may include an apparatus for use downholecomprising a cylindrical housing with a first end, a second end, anaxis, a first magnetic anomaly sensor located within the cylindricalhousing, a second magnetic anomaly sensor located within the cylindricalhousing and located a fixed axial distance from the first magneticanomaly sensor, a processor located within the cylindrical housing,operatively connected to the first magnetic anomaly sensor and thesecond magnetic anomaly sensor, wherein the processor compares themeasurements of the first magnetic anomaly sensor, the second magneticanomaly sensor, the time differential of those measurements, and withthe fixed axial distance between the two sensors, calculates theinstantaneous velocity of the tool and at least one radially retractablebraking arm located in the cylindrical housing, wherein the processorcan command the braking arm to extend against a wellbore and stop thedownhole descent of the apparatus at a predetermined location.

A variation of the example may include having a plurality of processors.It may have stored log data of the wellbore and compare that to the twomeasurements to fine tune the velocity calculation. The first magneticanomaly sensor may include a plurality of electromagnetic coils orientedabout the axis. The second magnetic anomaly sensor may include aplurality of electromagnetic coils wrapped oriented about the axis. Thecylindrical housing may be composed of a frangible material. Thecylindrical housing may be composed of a ceramic material. Thecylindrical housing may be composed of steel. The processor maycalculate the distance traveled by the tool based on the calculatedinstantaneous velocity. The processor may calculate the distancetraveled by the tool by integrating the calculated velocity with respectto time. The processor may calculate the distance traveled by the toolusing summation of the calculated velocity with respect to time. Theprocessor may calculate the distance traveled by the tool by averagingthe calculated velocity over a plurality of measurements and multiplyingby time. The processor may calculate the distance traveled by the toolusing a piecewise summation with respect to time. The at least oneradially retractable braking arm may be a plurality of braking arms.

An example embodiment may include a method for determining the locationof a tool in a wellbore comprising measuring a first borehole magneticanomaly with respect to time at a first location on a tool, measuringthe first borehole magnetic anomaly with respect to time at a secondlocation on a tool a predetermined distance from first location,comparing the time difference between the first magnetic anomaly at thefirst location with the first magnetic anomaly at the second location,calculating the velocity of the tool based on the comparison of the timedifference of the first magnetic anomaly at the first location with thefirst magnetic anomaly at the second location, the time, and thedistance between the first location and the second location, calculatingthe distance traveled by the tool based on the velocity calculation,deploying at least one braking arm when the location of the toolapproaches predetermined location, stopping the tool at thepredetermined location; and activating a downhole device at thepredetermined location.

A variation of the example embodiment may include executing apreprogrammed function when the tool travels a predetermined distance.It may include comparing the measured first magnetic anomaly at thefirst location with log data. It may correct the measured first magneticanomaly at the first location with log data. It may compare the measuredfirst magnetic anomaly at the second location with log data. It maycorrect the measured first magnetic anomaly at the second location withlog data. It may measure time to determine the time differential betweenthe measurement at the first location and the measurement at the secondlocation. It may generate a first electromagnetic field. It may generatea second electromagnetic field. The calculation of the distance mayinclude integrating the calculated velocity with respect to time.Calculating the distance may include summation of the calculatedvelocity with respect to time. Calculating the distance may includeaveraging the calculated velocity over a plurality of measurements andmultiplying by time. Calculating the distance may include a piecewisesummation with respect to time. Activating a downhole device at apredetermined location may include explosively perforating a wellbore,setting a bridge plug, setting an expandable or explosively cutting atubular.

An example embodiment may be a system for use downhole including aplugging tool having a cylindrical housing, a first end, a distal end,an axis, and a packer, an autonomous tool with a first end, a secondend, located coaxial with the axis, wherein the second end of theautonomous tool is coupled to the first end of the plugging tool, theautonomous tool further comprising, a top housing with a first end, asecond end, located coaxial with the axis, a bottom housing with a firstend located proximate to the second end of the top housing, and a secondend, wherein the bottom housing is coaxial with the axis, a firstmagnetic anomaly sensor located within the first housing, a secondmagnetic anomaly sensor located with the second housing, and a processorlocated within the top housing, operatively connected to the firstmagnetic anomaly sensor and the second magnetic anomaly sensor, whereinthe processor compares data from the first magnetic anomaly sensor andthe second magnetic anomaly sensor to determine the velocity of theautonomous tool and then calculating the distance the autonomous toolhas traveled downhole using the calculated velocity.

A variation of the example embodiment may have a plurality ofelectromagnetic coils disposed within the first magnetic anomaly sensor.A first electromagnetic coil may be disposed within the first magneticanomaly sensor adapted to generate an electromagnetic field. A secondelectromagnetic coil may be disposed within the first magnetic anomalysensor adapted to generate an electromagnetic field. A thirdelectromagnetic coil may be disposed within the first magnetic anomalysensor adapted to detect an electromagnetic field. A fourthelectromagnetic coil may be disposed within the first magnetic anomalysensor adapted to detect an electromagnetic field. A fifthelectromagnetic coil may be disposed within the first magnetic anomalysensor adapted to detect an electromagnetic field. A sixthelectromagnetic coil may be disposed within the first magnetic anomalysensor adapted to detect an electromagnetic field.

Further variations of the example embodiment may include a first subbeing coupled to the first end of the top housing. A second sub may becoupled to the second end of the top housing and coupled to the firstend of the bottom housing. A third sub may be coupled to the second endof the bottom housing. The first centralizer may have a hollowcylindrical shape. The second centralizer may have a substantiallyhollow cylindrical shape. A cylindrical core may be located coaxial withthe axis and passing through the first, second, third, fourth, fifth,and sixth electromagnets. It may include a plurality of electromagneticcoils disposed within the second magnetic anomaly sensor. A seventhelectromagnetic coil may be disposed within the second magnetic anomalysensor adapted to generate an electromagnetic field. An eighthelectromagnetic coil may be disposed within the second magnetic anomalysensor adapted to generate an electromagnetic field. A ninthelectromagnetic coil may be disposed within the second magnetic anomalysensor adapted to detect an electromagnetic field. A tenthelectromagnetic coil may be disposed within the second magnetic anomalysensor adapted to detect an electromagnetic field. An eleventhelectromagnetic coil may be disposed within the second magnetic anomalysensor adapted to detect an electromagnetic field. A twelfthelectromagnetic coil may be disposed within the second magnetic anomalysensor adapted to detect an electromagnetic field.

Further variations of the example embodiment may include a cylindricalcore located coaxial with the axis and passing through the first,second, third, fourth, fifth, and sixth electromagnets. The processormay include a data logger. The processor may include a plurality ofprocessors. The processor may compute the velocity by comparingmeasurements taken from the first magnetic anomaly sensor and the secondmagnetic anomaly sensor. A first centralizer may surround a portion ofthe first end of the top housing. A second centralizer may surround aportion of the second end of the top housing and a portion of the secondend of the bottom housing. The top housing may be composed of afrangible material. The top housing may be composed of a ceramicmaterial. The top housing may be composed of steel. The bottom housingmay be composed of a frangible material. The bottom housing may becomposed of a ceramic material. The bottom housing may be composed ofsteel. The packer may be composed of metal. The packer may be composedof a hard rubber. A braking assembly may be coupled to the first end ofthe top housing. A jet cutter may be coupled to the braking assembly. Ajet cutter may be coupled to autonomous tool.

Further variations of the disclosed embodiments may include theprocessor calculating the distance traveled by the tool based on thecalculated instantaneous velocity. The processor may calculate thedistance traveled by the tool by integrating the calculated velocitywith respect to time. The processor may calculate the distance traveledby the tool using summation of the calculated velocity with respect totime. The processor may calculate the distance traveled by the tool byaveraging the calculated velocity over a plurality of measurements andmultiplying by time. The processor may calculate the distance traveledby the tool using a piecewise summation with respect to time.

An example embodiment may include a method for locating a downhole toolcomprising inserting an autonomous tool into a borehole, moving theautonomous tool down the borehole, programming the autonomous tool toexecute a command at a predetermined location within the borehole,detecting a set of borehole magnetic anomalies at a first location onthe autonomous tool, detecting the set of borehole magnetic anomalies ata second location on the autonomous tool, comparing the detection at thefirst location with the detection at the second location, calculatingthe velocity of the autonomous tool based on the comparison the set ofborehole magnetic anomalies measured at the first location and secondlocation, calculating the position of the tool based on the calculatedvelocity, automatically braking the autonomous tool as it approaches apredetermined location, holding the autonomous tool at a predeterminedlocation, and activating at least one downhole device at thepredetermined location.

A variation of the embodiment may include the autonomous tool generatingan electromagnetic field at a first location in the autonomous tool. Theautonomous tool may generate an electromagnetic field at a secondlocation in the autonomous tool. It may detect casing collars based onthe detected borehole magnetic anomalies. It may execute a command tofire a perforating gun. It may execute a command to deploy a brakeassembly. It may execute a command to fire a pipe severing tool. It mayexecuted a command to expand a plug within the borehole. It may move theautonomous tool by dropping it down a wellbore. Moving the autonomoustool may include pumping it down a wellbore. It may calculate theposition by integrating the calculated velocity with respect to time. Itmay calculate the position by a summation of the calculated velocitywith respect to time. It may calculate the position by averaging thecalculated velocity over a plurality of measurements and multiplying bytime. It may calculate the position of the tool using a piecewisesummation with respect to time. Activating a downhole device at apredetermined location may include explosively perforating a wellbore,setting a bridge plug, setting an expandable or cutting a tubular.

BRIEF DESCRIPTION OF THE DRAWINGS

For a thorough understanding of the present invention, reference is madeto the following detailed description of the preferred embodiments,taken in conjunction with the accompanying drawings in which referencenumbers designate like or similar elements throughout the severalfigures of the drawing. Briefly:

FIG. 1 shows an example embodiment of an autonomous downhole toolcoupled to a casing collar locator.

FIG. 2 shows an example embodiment of an autonomous downhole toolcoupled to a centralizer and a fishing neck.

FIG. 3 shows an example embodiment of an autonomous downhole toolcoupled to firing head assembly, a brake assembly, and a setting tool.

FIG. 4 shows an example embodiment of an autonomous downhole toolcoupled to firing head assembly, a brake assembly with the brake padsextended, and a setting tool.

FIG. 5 shows an example embodiment of an autonomous downhole toolcoupled to two casing collar locators.

FIG. 6 shows an example embodiment of an autonomous downhole toolcoupled to two casing collar locators and a cutter.

FIG. 7 shows an example embodiment of an autonomous downhole toolcoupled to two casing collar locators and a perforating gun.

DETAILED DESCRIPTION OF EXAMPLES OF THE INVENTION

In the following description, certain terms have been used for brevity,clarity, and examples. No unnecessary limitations are to be impliedtherefrom and such terms are used for descriptive purposes only and areintended to be broadly construed. The different apparatus, systems andmethod steps described herein may be used alone or in combination withother apparatus, systems and method steps. It is to be expected thatvarious equivalents, alternatives, and modifications are possible withinthe scope of the appended claims.

For plug and abandonment applications in oil wells, a cutter and/or plugmust be sent downhole, via electric line or tubing, in a single orseparate trip, in order to plug the tubular and then cut to retrieve theremaining tubular to surface. This process is costly due to rig timeduring the conveyance process and the logistics of getting theconveyance unit to the well site. Using autonomous technology, a cutter,a plug and/or a combination of a cutter and plug, could be droppeddownhole without being tied to any conveyance, self-navigate, andperform its purpose at a pre-determined depth because the well will beabandoned, there is no worry about leaving the remnants of theautonomous tool at the bottom of the well.

An example embodiment is shown in FIG. 1 of a tool assembly 10 withsensor 15 disposed within a housing and an electronics and batterysection 14 15 disposed within a housing having programming/wiring ports13 and 16, and lanyard switch 12. The sensor 15 may be a magneticanomaly detector, such as a casing collar locator. Pressure safetyswitch 11 keep safe the ballistic hardware, such as casing cutters,braking mechanisms, setting tools and casing plugs, that can be attachedto the tool until a depth in the well has been reached in where thehydrostatic pressure exerted by the fluids in the well are great enoughto move the safety switch 11 from the safe mode to the armed mode. Thesensor 15 is used to detect magnetic anomalies, such as casingconnections and collars, and use these anomalies to determine the toolsvelocity and location as the tool descends into the well. The magneticanomalies can be any unique magnetic feature in the tubing or casing andnot limited only to collars or connections.

The electronics and battery section 14 contain a processor or aplurality of processors. The electronics and battery section 14 mayinclude a data logger coupled to at least one processor. The processorcomputes the location of the tool using measurements taken from thesensor 15. Upon reaching a predetermined depth in the well whoselocation was determined by the electronics and battery section 14, theprocessor will initiate a preprogrammed event or events. These eventscan be the firing of a cutter to cut tubing or casing, the actuating ofa braking mechanism to stop the tools decent, the initiation of aballistic setting tool to set a plug in the tubing or casing, or acombination of the forgoing events. Programming and configuration of thetool 10 is accomplished by connecting the tool 10 to a computer via theprogramming/wiring ports 13 and 16.

Prior to connecting any ballistic elements (cutters, brakes or settingtools) to the tool 10, the electrical connections of the pressure safetyswitch 11 is checked to ensure that they are electrically shorted. Theseswitches ensure that when ballistic elements are connected to the tool,no unintentional electrical energy can be applied to the ballisticelements until a predetermined hydrostatic well pressure has beenexceeded. The pressure safety switch 11 is constructed using a springloaded differential piston actuator in which one side of the piston'ssurface area is much larger than the other. The larger side of thepiston is spring loaded with a spring of a known compression rate. Whenthe differential piston actuator is exposed to external hydrostaticpressures, the hydrostatic pressure effectively applies a greater forceto the side of the piston with the larger surface area than it does tothe side of the piston with the smaller surface area. This differentialpressure causes the larger side of the piston to move against the springload. At hydrostatic pressures greater than 700 PSI, the differentialpiston actuator has moved enough to remove the connection that wasshorting the connection between the electronics & battery section andthe ballistic element.

The lanyard switch 12 is an electro-mechanical switch that must beactivated before the tool will start looking for magnetic anomalies andstart calculating its velocity and the distance traveled. This switchmay be activated by the removal of a safety clip attached to a lanyardwhen the tool is released to fall into the well.

An example embodiment is shown in FIG. 2 of a tool assembly 10 fromFIG. 1. The tool assembly 10 is coupled to a firing head assembly 24having a tubular cutter 23 attached. A centralizer 22 is also showncoupled above the cutter 23. A fishing neck 21 is located above thecentralizer 22. The sensor 15 is used to detect magnetic anomalies, suchas casing connections and collars, and use these anomalies to determinethe tools velocity and location as the tool descends into the well. Themagnetic anomalies can be any unique magnetic feature in the tubing orcasing and not limited only to collars or connections.

An example embodiment is shown in FIG. 3 with a tool assembly 50 isconfigured with a cutter 23, a ballistic braking system 26 15 disposedwithin a housing, a setting tool 27 15 disposed within a housing, and acasing plug 28. The tool assembly 50 also includes a fishing neck 21, acentralizer 22, and a firing head assembly 24. The ballistic brakingsystem 26 includes at least one radially retractable braking arm 29. Inthis configuration the ballistic braking system 26 is shown with theradially retractable braking arm 29 fully retracted.

After launching and upon reaching a predetermined depth in the well, theautonomous tool 10 fires the ballistic braking system 26. Firing theballistic brake system 26 releases the spring loaded braking arms 29from the body of the ballistic brake, allowing the braking arms 29 todig into the inside walls of the casing or tubing, thus slowing andstopping the decent of the tool assembly 50. Around the same time thebraking arms 29 are released and an igniter in the setting tool 27 isactivated, thus initiating the operation of the setting tool 27. Thesetting tool 27 generates the mechanical force necessary to set the plug28 in the casing by using gas pressure generated by a slow burningpyrotechnic contained within the body of the setting tool 27.Immediately upon detecting the shock generated by the setting tool 27when the plug 28 has been set, the autonomous tool 10 will fire thecutter 23, thus severing the casing. The casing or tubing can then beremoved and the tool assembly 50, along with its attachments, can beabandoned in the well. The sensor 15 is used to detect magneticanomalies, such as casing connections and collars, and use theseanomalies to determine the tools velocity and location as the tooldescends into the well. The magnetic anomalies can be any uniquemagnetic feature in the tubing or casing and not limited only to collarsor connections.

An example embodiment is shown in FIG. 4 with a tool assembly 50 isconfigured with a cutter 23, a ballistic braking system 26, setting tool27 and a casing plug 28. The tool assembly 50 also includes a fishingneck 21, a centralizer 22, and a firing head assembly 24. Afterlaunching and upon reaching a predetermined depth in the well, theautonomous tool 10 fires the ballistic braking system 26. Firing theballistic brake system 26 releases the spring loaded braking arms 29from the body of the ballistic brake, allowing the braking arms 29 todig into the inside walls of the casing or tubing, thus slowing andstopping the decent of the tool assembly 50. Around the same time thebraking arms 29 are released and an igniter in the setting tool 27 isactivated, thus initiating the operation of the setting tool 27. Thesetting tool 27 generates the mechanical force necessary to set the plug28 in the casing by using gas pressure generated by a slow burningpyrotechnic contained within the body of the setting tool 27.Immediately upon detecting the shock generated by the setting tool 27when the plug 28 has been set, the autonomous tool 10 will fire thecutter 23, thus severing the casing. The casing or tubing can then beremoved and the tool assembly 50, along with its attachments, can beabandoned in the well. The depiction in FIG. 4 shows the braking arms 29of the ballistic brake system 26 in the deployed configuration.

An example embodiment is shown in FIG. 5 of a tool assembly 30 with twomatched differential velocity sensors 35 and 37, each 15 disposed withina its own housing, are separated on an axis of a known distance by ahousing assembly containing an electronics and battery section 34,having programming/wiring ports 33 and 36, and lanyard switch 32. Thedifferential velocity sensors 35 and 37 may be matched differentialmagnetic anomaly sensors or equivalent casing collar locators. Pressuresafety switches 31 and 38 are positioned at the end of each of thedifferential velocity sensors 35 and 37, respectfully, that render theballistic hardware, such as casing cutters, braking mechanisms, settingtools and casing plugs, that can be attached to the tool safe until adepth in the well has been reached in where the hydrostatic pressureexerted by the fluids in the well are great enough to move the safetyswitches 31 and 38 from the safe mode to the armed mode. The safetyswitches 31 and 38 must be moved to the armed mode before any ballisticevent can be activated.

The matched differential velocity sensors 35 and 37 are used to detectmagnetic anomalies, such as casing connections and collars, and usethese anomalies to determine the tool's velocity as the tool descendsinto the well. Matching the differential velocity sensors 35 and 37provides for increased accuracy in identifying the magnetic anomaliesand their position within the tubing or casing string. The magneticanomalies can be any unique magnetic feature in the tubing or casing andnot limited only to collars or connections.

The disclosed sensors may be a magnetic anomaly detector, whichgenerally includes a plurality of electromagnetic coils disposedtherein. It may have a first electromagnetic coil disposed within themagnetic anomaly sensor adapted to generate an electromagnetic field.There may be a second electromagnetic coil disposed within the magneticanomaly sensor adapted to generate an electromagnetic field. There maybe a third electromagnetic coil disposed within the magnetic anomalysensor adapted to detect an electromagnetic field. There may be a fourthelectromagnetic coil disposed within the magnetic anomaly sensor adaptedto detect an electromagnetic field. There may be a fifth electromagneticcoil disposed within the magnetic anomaly sensor adapted to detect anelectromagnetic field. There may be a sixth electromagnetic coildisposed within the magnetic anomaly sensor adapted to detect anelectromagnetic field.

The electronics and battery section 34 contains a processor or aplurality of processors. The processor computes the velocity of the toolby comparing measurements taken from the first matched differentialvelocity sensor 35 and the second differential velocity sensor 37. Theprocessor calculates distance traveled by integrating the calculatedvelocity with respect to time. The processor calculates the distancetraveled using a summation of the calculated velocity with respect totime. The processor can also calculate the distance traveled byaveraging the calculated velocity over a plurality of measurements andmultiplying by time. The processor may also calculate the distancetraveled using a piecewise summation with respect to time. Upon reachinga predetermined depth in the well whose location was determined by thetool's time/velocity calculations, the processor will initiate apreprogrammed event or events. These events can include activating adownhole device, such as firing a cutter to cut tubing or casing, theactuating of a braking mechanism to stop the tools decent, theinitiation of a ballistic setting tool to set a plug in the tubing orcasing, activating a perforating gun, or a combination of the forgoingevents.

Programming and configuration of the tool 30 is accomplished byconnecting the tool 30 to a computer via the programming/wiring ports 33and 36. The programming/wiring port cover is removed to allow access tothe USB connector mounted within programming/wiring ports 33 and 36. Thetool may be configured by entering the predetermined depth the event isto take place, the events to be initiated, and the casing or tubingprofile. The casing or tubing profile is a sequential list of theindividual length of the pieces of casing or tubing that is in the well,normally starting from the surface to the bottom of the well. After thetool 30 has been configured, it is placed in a low power standby mode,computer connections are removed and the covers for theprogramming/wiring port 33 and 36 are secured back into position.

Prior to connecting any ballistic elements (cutters, brakes or settingtools) to the tool 30, the electrical connections of the pressure safetyswitches 31 and 38 are checked to ensure that they are electricallyshorted. These switches ensure that when ballistic elements areconnected to the tool, no unintentional electrical energy can be appliedto the ballistic elements until a predetermined hydrostatic wellpressure has been exceeded. The pressure safety switches 31 and 38 areconstructed using a spring loaded differential piston actuator in whichone side of the piston's surface area is much larger than the other. Thelarger side of the piston is spring loaded with a spring of a knowncompression rate. When the differential piston actuator is exposed toexternal hydrostatic pressures, the hydrostatic pressure effectivelyapplies a greater force to the side of the piston with the largersurface area than it does to the side of the piston with the smallersurface area. This differential pressure causes the larger side of thepiston to move against the spring load. At hydrostatic pressures greaterthan 700 PSI, the differential piston actuator has moved enough toremove the connection that was shorting the connection between theelectronics & battery section and the ballistic element.

The lanyard switch 32 is an electro-mechanical switch that must beactivated before the tool will start looking for magnetic anomalies andstart calculating its velocity and the distance traveled. This switchmay be activated by the removal of a safety clip attached to a lanyardwhen the tool is released to fall into the well.

An example embodiment is shown in FIG. 6 with an autonomous tool 45 in acutter only configuration assembly 40. A firing head 44 is attachedabove the tool 45. A centralizer 42 is also attached to prevent damageto the cutter 43 as the tool 40 drops into a well. The fish neck 41attaches above the tool 45 and provides a means to temporarily attachhandling equipment to the tool assembly 40 to facilitate its insertionin the well. In this mode of operation, the cutter 43 will be fired at apredetermined depth while the tool 45 is traveling down the well. Afterfiring the cutter 41 the tool continues on to the bottom of the well. Atthe bottom of the well or after a period of time the tool will turnitself off and automatically discharge any remaining energy in thebattery. Pressure safety switch 31 is positioned at the end of each ofthe differential velocity sensor 35. The lanyard switch 32 is anelectro-mechanical switch that must be activated before the tool willstart looking for magnetic anomalies and start calculating its velocityand the distance traveled. The electronics and battery section 34contains a processor or a plurality of processors. The processorcomputes the velocity of the tool by comparing measurements taken fromthe first matched differential velocity sensor 35 and the seconddifferential velocity sensor 37. The differential velocity sensors 35and 37 may be matched differential magnetic anomaly sensors orequivalent casing collar locators. Programming and configuration of thetool 56 is accomplished by connecting the tool 56 to a computer via theprogramming/wiring ports 33 and 36.

An example embodiment is shown in FIG. 7 with an autonomous tool 56 in aperforating gun configuration assembly 50. Centralizers 52 and 42protect the perforating gun 54 as the autonomous tool 56 drops into awell. The fish neck 41 attaches above the perforating gun 54 andprovides a means to temporarily attach handling equipment to the tool 56to facilitate its insertion in the well. In this mode of operation, theperforating gun 54 with its plug/shot assembly 53 and top fire assembly55 will be fired at a predetermined depth while the tool 56 is travelingdown the well. After firing the perforating gun 54 the tool 56 continueson to the bottom of the well. At the bottom of the well or after aperiod of time the tool will turn itself off and automatically dischargeany remaining energy in the battery. The lanyard switch 32 is anelectro-mechanical switch that must be activated before the tool willstart looking for magnetic anomalies and start calculating its velocityand the distance traveled. The electronics and battery section 34contains a processor or a plurality of processors. The processorcomputes the velocity of the tool by comparing measurements taken fromthe first matched differential velocity sensor 35 and the seconddifferential velocity sensor 37. The differential velocity sensors 35and 37 may be matched differential magnetic anomaly sensors orequivalent casing collar locators. Programming and configuration of thetool 56 is accomplished by connecting the tool 56 to a computer via theprogramming/wiring ports 33 and 36.

The autonomous tool and its attachments will be assembled and armed onsurface at the wellsite. The electronics section will be uploaded withthe tally for depth correlation (such as a casing collar locator or“CCL”) and target initiation depths via a USB programming port that isaccessible through the programming/wiring ports. The tools will bedropped in the well via custom launching equipment. When the tool drops,the lanyard will disconnect from the launching system “turning the toolon”. The autonomous tool will fall via gravity or be pumped fromsurface. For safety, adequate hydrostatic pressure must be present toconnect the firing circuit to the Electronics section. The tool will usethe matched differential velocity sensors or matched differentialmagnetic anomaly sensors (such as a casing collar locator or “CCL”)located at each end of the Tool and acceleration algorithms toself-navigate to programmed depths and then initiate the cutter, and/orthe braking system, setting tool and plug. These initiations couldhappen simultaneously or at different predetermined depths. The remnantsof the autonomous tool and its attachments would be left downhole.

One of the purposes of the disclosed embodiments is to accuratelyidentify casing collars as the tool is either freefalling or beingpumped down a cased hole. Pumping the tool downhole may be necessary forhorizontal wells. One issue is that there are other anomalies that mayconfuse a more traditional casing collar locator. The use of twodifferential spaced magnetic sensors and digital signal processingmatching algorithms may continuously determine the velocity of the tool.The tool may then calculate the distance the tool has traveled. Thedistance calculation may include integrating the velocity over time,summation of the discrete velocity data, average the velocityinformation multiplied by time, or a piecewise summation method. Thetool may start measuring velocity as soon as it enters the wellbore. Thetool may use collars, anomalies, and/or both to determine velocity. Bydetermining the distance traveled accurately, the tool can performcertain functions at a pre-determined location in the well includingsetting a plug, cutting pipe, or detonating a perforating gun.

Although the invention has been described in terms of particularembodiments which are set forth in detail, it should be understood thatthis is by illustration only and that the invention is not necessarilylimited thereto. For example, terms such as upper and lower or top andbottom can be substituted with uphole and downhole, respectfully. Topand bottom could be left and right, respectively. Uphole and downholecould be shown in figures as left and right, respectively, or top andbottom, respectively. Generally downhole tools initially enter theborehole in a vertical orientation, but since some boreholes end uphorizontal, the orientation of the tool may change. In that casedownhole, lower, or bottom is generally a component in the tool stringthat enters the borehole before a component referred to as uphole,upper, or top, relatively speaking. The first housing and second housingmay be top housing and bottom housing, respectfully. In a gun stringsuch as described herein, the first gun may be the uphole gun or thedownhole gun, same for the second gun, and the uphole or downholereferences can be swapped as they are merely used to describe thelocation relationship of the various components. Terms like wellbore,borehole, well, bore, oil well, and other alternatives may be usedsynonymously. Terms like tool string, tool, perforating gun string, gunstring, or downhole tools, and other alternatives may be usedsynonymously. A tool, tool string, or tool assembly is generallycylindrical in shape and has a common axis that is shared by most of thecylindrical components. This common axis is generally parallel orcoaxial with the center axis of the wellbore or casing that the toolstring is located. Each component may be contained within its ownhousing or they may be grouped within a common housing. The axis of awellbore or casing changes with depth as a well may start vertical, butthen gradually become horizontal at a certain depth within the earth.Therefore, the common axis, terms such as uphole or downhole, are allrelative in that in a horizontal or deviated well the terms are stillused as if the well were vertical. The alternative embodiments andoperating techniques will become apparent to those of ordinary skill inthe art in view of the present disclosure. Accordingly, modifications ofthe invention are contemplated which may be made without departing fromthe spirit of the claimed invention.

What is claimed is:
 1. A method for locating a downhole tool comprising:inserting an autonomous tool into a borehole; moving the autonomous tooldown the borehole; programming the autonomous tool to execute a commandat a predetermined location within the borehole; detecting a set ofborehole magnetic anomalies at a first location on the autonomous tool;detecting the set of borehole magnetic anomalies at a second location onthe autonomous tool; comparing the detection at the first location withthe detection at the second location; calculating the velocity of theautonomous tool based on the comparison the set of borehole magneticanomalies measured at the first location and second location;calculating the position of the tool based on the calculated velocity;automatically braking the autonomous tool as it approaches apredetermined location; holding the autonomous tool at a predeterminedlocation; and activating at least one downhole device at thepredetermined location.
 2. The method of claim 1 further comprising theautonomous tool generating an electromagnetic field at a first locationin the autonomous tool.
 3. The method of claim 2 further comprising theautonomous tool generating an electromagnetic field at a second locationin the autonomous tool.
 4. The method of claim 1 further comprisingdetecting casing collars based on the detected borehole magneticanomalies.
 5. The method of claim 1 wherein the executed command is tofire a perforating gun.
 6. The method of claim 1 wherein the executedcommand is to deploy a brake assembly.
 7. The method of claim 1 whereinthe executed command is to fire a pipe severing tool.
 8. The method ofclaim 1 wherein the executed command is to expand a plug within theborehole.
 9. The method of claim 1 wherein moving the autonomous toolincludes dropping it down a wellbore.
 10. The method of claim 1 whereinmoving the autonomous tool includes pumping it down a wellbore.
 11. Themethod of claim 1 wherein the calculating the position includesintegrating the calculated velocity with respect to time.
 12. The methodof claim 1 wherein the calculating the position includes summation ofthe calculated velocity with respect to time.
 13. The method of claim 1wherein the calculating the position includes averaging the calculatedvelocity over a plurality of measurements and multiplying by time. 14.The method of claim 1 wherein the calculating the position includes apiecewise summation with respect to time.
 15. The method of claim 1wherein activating a downhole device includes explosively perforating awellbore.
 16. The method of claim 1 wherein activating a downhole deviceincludes setting a bridge plug.
 17. The method of claim 1 whereinactivating a downhole device includes setting an expandable.
 18. Themethod of claim 1 wherein activating a downhole device includes cuttinga tubular.
 19. The method of claim 1 further comprising releasing theautonomous tool from the first predetermined location, traveling to asecond predetermined location, and holding the autonomous tool at thesecond predetermined location.
 20. The method of claim 1 furthercomprising activating a plurality of downhole devices at a plurality ofcorresponding predetermined locations.